four years of operating experience with dryfining fuel ... · pdf filefour years of operating...

Journal of Energy and Power Engineering 9 (2015) 526-538 doi: 10.17265/1934-8975/2015.06.003

Four Years of Operating Experience with DryFiningTM

Fuel Enhancement Process at Coal Creek Generating

Station

Nenad Sarunac1, Charles W. Bullinger2 and Mark Ness2

1. Department of Mechanical Engineering and Engineering Science, University of North Carolina at Charlotte, Charlotte NC 28223, USA

2. Great River Energy, Coal Creek Station, Underwood ND 58576, USA

Received: October 14, 2014 / Accepted: February 09, 2015 / Published: June 30, 2015. Abstract: Lignite and sub-bituminous coals from western U.S. contain high amounts of moisture (sub-bituminous: 15%-30%, lignites: 25%-40%). German and Australian lignites (brown coals) have even higher moisture content, 50% and 60%, respectively. The high moisture content causes a reduction in plant performance and higher emissions, compared to the bituminous (hard) coals. Despite their high-moisture content, lignite and sub-bituminous coals from the western U.S. and worldwide are attractive due to their abundance, low cost, low NOx and SOx emissions, and high reactivity. A novel low-temperature coal drying process employing a fluidized bed dryer and waste heat was developed in the U.S. by a team led by GRE (Great River Energy). Demonstration of the technology was conducted with the U.S. Department of Energy and GRE funding at Coal Creek Station Unit 1. Following the successful demonstration, the low-temperature coal drying technology was commercialized by GRE under the trade name DryFiningTM fuel enhancement process and implemented at both units at Coal Creek Station. The coal drying system at Coal Creek has been in a continuous commercial operation since December 2009. By implementing DryFining at Coal Creek, GRE avoided $366 million in capital expenditures, which would otherwise be needed to comply with emission regulations. Four years of operating experience is described in this paper. Key words: Power generation, pulverized coal combustion, high-moisture coals, coal beneficiation, efficiency improvement, emissions reduction.

1. Introduction

The low-rank, high-moisture coals constitute about

50% of the U.S. and world coal reserves. Given the

abundance of these low-cost coals, the use of

high-moisture coal for power generation is common

and growing. Despite their high-moisture content,

lignite and sub-bituminous coals from the western U.S.

and low-rank coals worldwide are attractive due to

their low NOx and SOx emissions and high reactivity,

compared to bituminous (hard) coals. In the U.S. alone,

279 power facilities burn high moisture coals such as

lignite and PRB (Powder River Basin) sub-bituminous

Corresponding author: Nenad Sarunac, associate professor,

research fields: efficiency improvement, thermal drying of high-moisture coals and waste heat utilization. E-mail: [email protected].

coal. These plants produce nearly a third of the coal

fired electric generation in the U.S. [1].

When high-moisture coals, such as lignite, are

burned in utility boilers, about 7% of the fuel heat input

is used to evaporate and superheat fuel moisture. As

presented in Fig. 1, most of this loss is associated with

latent heat of evaporation of fuel moisture. The use of

high-moisture, low HHV (higher heating value) coals,

results in higher fuel and flue gas flow rates, auxiliary

power use, net unit heat rate, and mill, coal pipe and

burner maintenance requirements compared to

bituminous (hard) coals.

To improve unit efficiency, plant operation and

economics, and reduce CO2 emissions from the

existing and future-built power plants firing low-rank

coals, countries with large resources of high-moisture

D DAVID PUBLISHING

Four Years of Operating Experience with DryFiningTM Fuel Enhancement Process at Coal Creek Generating Station

527

Fig. 1 Losses due to evaporation of coal moisture (raw and dried North Dakota lignite).

low-quality coals are developing coal dewatering and

drying processes. This is particularly important for

advanced PCC (pulverized coal combustion)

technology operating at high steam parameters.

However, many thermal processes developed thus

far are either quite complex or require costly primary

energy or steam to remove moisture from the coal. This

significantly increases process cost, which represents a

main barrier to industry acceptance of this technology.

A comprehensive review of coal drying technologies is

provided in Ref. [2].

2. DryFiningTM: A-Low Temperature Coal Drying Process

A novel low-temperature coal drying process

employing a moving bed FBD (fluidized bed dryer)

and using waste heat to decrease moisture content of

low-rank coals was developed in the U.S. by a team

led by GRE (Great River Energy).

2.1 DryFining Development

During the 1990’s, the engineering staff at Coal

Creek Station began investigating alternative

approaches to dealing with future emission regulations.

Conventional approaches included changing fuels

and/or adding environmental control equipment and,

often, resulted in lowering emissions at the expense of

increases in unit heat rate and operating and

maintenance costs. Higher heat rate results in higher

required fuel heat input, higher CO2 emissions and

higher flow rate of flue gas leaving the boiler, and

lower plant capacity due to higher station service

power requirements or limited equipment capacity.

Increased flue gas flow rate requires a larger size of

environmental control equipment, higher equipment

cost and station service power.

The alternative to traditional approaches involves

improvement in coal quality, which in case of the

high-moisture coals, may be achieved by removing a

portion of coal moisture.

A systematic phased approach to development of a

coal drying technology was initiated by GRE in 1997

by performing analyses to quantify benefits of coal

drying, small-scale experiments, and large-scale burn

tests where dried coal was burned in Unit 1 boiler in

2002 to verify theoretical findings [3].

The next project phase involved coal drying tests

conducted at a pilot-scale (2 t/h) fluidized bed coal

dryer located at Coal Creek Station (2 × 600 MWgross

subcritical) located in Underwood, ND, and

laboratory-scale coal drying tests conducted at Lehigh

University to determine drying kinetics and create

analytical model of the coal drying process in a FBD.

A moving bed FBD was selected due to its high

heat and mass transfer coefficients which produce a

compact dryer design. The air is employed as a

fluidization medium instead of commonly used steam1.

Potential devolatization of coal is avoided by

performing drying with plant low-grade waste heat.

Following successful testing and operation of the

pilot-scale dryer, a prototype-scale (75 t/h) FBD was

designed, built, tested, and operated at Coal Creek

Station during the time period from 2005 to 2007. A

series of controlled tests was performed to establish

performance characteristics of the dryer and gain

operating experience. Test results are described in

Refs. [4-6].

1Inert fluids, other than steam, may be used for fluidization to achieve deep reductions in coal moisture content.


528

Based on a successful operation of the prototype

drier, and considering co-benefits of coal cleaning,

GRE decided to implement the full-scale coal drying

and cleaning system at Units 1 and 2 at Coal Creek

Station in 2007. The system design allowed tie in with

the plant equipment while both units were on line,

requiring no down time.

The coal drying and cleaning technology was

commercialized by GRE in 2009, and is available

under trade name DryFiningTM fuel enhancement

process. The DryFining system has been in continuous

commercial operation at Coal Creek Station since

December 2009.

2.2 Process Description

A two-stage moving bed FBD is the heart of the

DryFining system. A schematic representation of a

dryer is presented in Fig. 2.

The FBD, developed by GRE, accomplishes two

important functions. It cleans the coal by removing a

significant portion of sulfur (S) and mercury (Hg)

from the raw coal in the first stage, and dries the coal

in the second stage. The cleaning function

distinguishes this coal drying technology and provides

a very important co-benefit of emissions reduction.

Crushed coal is fed to the first FBD stage where

non-fluidizable material such as rocks and other

higher-density fractions (“jetsam”) are segregated at

the bottom of the dryer, while less dense and smaller

particles (“floatsam”) are floating. Therefore, the

segregated stream, discharged from the dryer, has

higher mineral matter content (including pyrite), in

comparison to the dried coal (product stream).

Because most of the inorganically associated S is

contained in pyrite forms, as well as a considerable

fraction of Hg, in case of the ND lignite, about 30% of

S and Hg from coal are segregated out in the first

stage of the FBD [7].

The segregation tests performed with other lignites

and sub-bituminous coals have demonstrated similar

levels of S and Hg removal. The amount of segregated

Fig. 2 Schematic representation of a moving bed FBD.

sulfur and mercury depends on many factors, such as

percentage of inorganically associated sulfur in coal,

the presence or absence of clays, and other factors

related to coal morphology.

The fluidizable material next enters the second

stage of the dryer, where the surface and inherent

coal moisture are evaporated by the heat supplied

by the fluidizing air and the in-bed HXE (heat

exchanger). The in-bed heat exchanger increases

the temperature of the fluidizing (drying) air and

fluidized coal bed, improving drying kinetics (the rate

of coal drying). The drying process affects the

microstructure of coal particles that disintegrate

during drying. This reduction in coal particle size has

a significant positive effect on mill power. The drier

and finer coal is discharged from the FBD as the

product stream. The bed residence time and

temperature are the main parameters affecting the

residual moisture content.

2.3 DryFining Applications

DryFining may be retrofitted to the existing PCC

plants, integrated into the new-build PCC plants, as

well as coal gasification IGCC (integrated gasification

combined cycle) and CTL (coal-to-liquids), and low

rank coal-fired oxyfuel power plants employing dry

feed oxygen-blown gasifiers.

For existing units, depending on site specifics,

DryFining is capable of reducing coal moisture


529

content by 10% to 20%-points, with higher value

corresponding to the supercritical units. Higher

moisture reductions are possible for newly built units

where DryFining is integrated with a power plant, and

boiler is designed to burn dried coal.

Thermal integration of DryFining with an existing

power plant is site-specific and depends on the

available heat sources, space constraints, and general

layout of the plant. The benefits of coal drying, such

as heat rate improvement, increase as moisture content

of the raw coal and reduction in coal moisture increase.

For North American lignites containing approximately

40% moisture, the heat rate improvement is in the

3%-5% range2, while for the sub-bituminous coals

with lower moisture content (15%-30%), the heat rate

improvement is in the 2%-3% range.

Integration of DryFining into the newly built power

plants operating with high steam parameters is

especially beneficial for units burning low-rank coals,

since their efficiency is severely affected by the high

coal moisture content (Fig. 3). A reduction of coal

moisture is necessary to achieve the full benefits of

the advanced PCC technologies.

Additionally, in arid regions, capturing and recycling

the water vapor from the fuel prior to combustion can

provide additional water cycle benefits.

The achievable reduction in coal moisture content

may be limited by thermal performance of the boiler

convection pass, the amount of available heat or by

the equilibrium moisture content of coal3. A new plant

with integrated DryFining will have a lower initial

capital cost (CAPEX), compared to the plant burning

raw coal, including the front-end coal drying system,

and will not be limited by the convection pass

performance.

2For German and Australian brown coals containing 55%-60% moisture, the heat rate improvement is in the 5%-7% range. 3Oxyfuel, and oxygen-blown gasification plants are not subject to the equilibrium moisture content limit. The studies conducted with DryFining integrated with the lignite-fired oxyfuel and CTL (coal-to-liquid) plants employing dry-feed gasifier, have demonstrated coal moisture reduction from the 40%-55% range to the target moisture level of 8%-12%.

Fig. 3 Effect of coal rank and steam parameters on net unit efficiency (source: EPRI (Electric Power Research Institute)).

In addition, due to higher efficiency and lower flow

rate of flue gas, the size of the CCS (carbon capture

and storage) system and its adverse effect on plant

efficiency and capacity will be smaller.

According to four years of operating experience at

Coal Creek, DryFining also reduces operating cost

(OPEX).

3. Baseline Performance and Emissions

The coal drying and cleaning system at Coal Creek

is sized for 1,100 t/h of raw North Dakota lignite with

moisture content in the 40% range.

Controlled performance and emissions tests were

conducted on Coal Creek Unit 1 at full load (600 MWgross)

steady state operating conditions before (2009) and

after (2010) and (2011) the implementation of

DryFining, in order to establish baseline unit

performance and emissions, and quantify and

document the improvement. The results are reported in

Refs. [8, 9].

3.1 Operating Conditions

The operating conditions corresponding to the tests

performed with the wet and dried coal at Unit 1 are

summarized in Table 1.

With the dried coal, the APH (air preheater) air

leakage decreased due to the lower drafts and lower

gas- and air-side pressure drops associated with lower

flows of combustion air and flue gas (Table 2). In


530

Table 1 Unit 1 operating conditions with and without coal drying applied.

Test PG (MW) O2, APH, in

(%) APH leakage (%)

FGD inlet temp. (°F)

Stack temp. (°F) Opacity

Raw coal 600 2.54 8.2 345 188 6.6

Dried coal 606 2.76 4.1 309 156 5.8

Table 2 The effect of DryFining on the performance of Coal Creek Unit 1.

Test TM (%)

HHV (Btu/lb)

Coal used (klb/hr)

Flue gas (kscfm)

Mill power (kW)

ID fan power (kW)

HRnet (Btu/kWh)

Boiler efficiency (%)

Wet coal 37.1 6,251 946 1,557 3,989 8,767 10,246 80.34

Dried coal 32.1 6,914 856 1,467 3,596 7,251 9,890 83.06

Difference (%) -13.5 10.6 -9.5 -5.8 -9.9 -17.3 -3.5 3.4

addition, the temperature of flue gas at the APH exit

decreased, resulting in lower volumetric flow of flue

gas entering the FGD (flue gas desulfurization) system,

thus, allowing a larger proportion of the flue gas to be

scrubbed (Coal Creek employs a FGD gas bypass to

maintain dry stack conditions).

As a consequence of the lower FGD bypass flow,

the stack temperature decreased, but remained well

above saturation temperature. Also, with lower flue

gas flow and temperature, flue gas velocity through

the ESP (electrostatic precipitator) decreased, resulting

in improved particulate collection efficiency and

lower opacity.

3.2 Unit Performance

The effect of the DryFining process on HRnet (net

unit heat rate) and boiler efficiency (B), fuel and

stack flow, mill and ID (induced draft) fan power is

summarized in Table 2. During the 2011 tests, the coal

moisture content was reduced by 5%-points (or 13%)

resulting in approximately 11% increase in coal HHV.

Further reduction in coal moisture was limited by

steam temperatures, which began to decrease due to

lower flow rate of flue gas through the convective

pass of the boiler.

As a result of the lower coal flow rate, improved

grindability, and reduced size of dried coal, mill power

decreased by almost 10%. This allowed unit to be

operated with six mills in service, instead of customary

seven (or eight). Freeing up one of the mills to be used

as a spare improved plant availability, as mills can be

rotated in and out of service for routine maintenance or

repair without reducing fuel-processing capacity.

The volumetric flow rate of flue gas through the

stack decreased due to lower coal flow rate and lower

stack temperature, resulting in lower draft losses.

With drier coal, the net unit heat rate, determined by

the BTCE (boiler-turbine cycle efficiency) method,

decreased by 3.5%. The boiler efficiency, determined

by the ASME PTC (American Association of

Mechanical Engineers, power test code) 4 method, has

increased by 3.4%. The improvement in net unit heat

rate is higher than the improvement in boiler efficiency

because, with drier coal, the combined fan and mill

power are lower, compared to the wet coal.

The change in CO2 emissions is traditionally related

to the change in net unit heat rate. That is, one percent

change in heat rate results in one percent change in CO2

emissions.

The reduction in CO2 emissions determined by using

the performance test data shown in Table 2 was 3.5%.

Such a small difference is difficult to measure,

considering the CEM (continuous emission monitor)

measurement accuracy and precision. The CO2

intensity was reduced by 3.0% (Table 3).

However, the heat rate reduction achieved at Coal

Creek is somewhat limited by site-specific conditions,

other power plants could potentially achieve greater

efficiency improvements. At Coal Creek, the planned

increase of the heat transfer surface in convective pass


531

Table 3 Effect of DryFining on emissions at Coal Creek Unit 1.

Test NOx (lb/MBtu)

SOx (lb/MBtu)

HgT (μg/dNm3 @3% O2)

CO2 intensity(lb/MWh)

Wet coal 0.284 0.578 14 2,209

Dried coal 0.200 0.346 8.5-9 2,144

Reduction (%) 30 > 40 35-40 3.0

of the boiler will allow further reductions in the coal

moisture content, with a projected heat rate improvement

and CO2 emissions reduction of 4.5%.

3.3 Emissions

3.3.1 NOx Emissions

Implementation of DryFining had a significant

positive effect on NOx, SO2, and Hg emissions (Table 3).

A reduction in NOx emissions is attributed to the

lower coal input, and lower PA (primary air) to SA

(secondary air) flow ratio, compared to the wet coal

operation. The lower PA flow results in lower NOx

formation at the burners, while the higher SA flow

allows for deeper furnace staging, with more overfire

air available for SOFAs (separated overfire airs). The

resulting 30% NOx reduction allowed Coal Creek to

meet its new NOx emission limits by boiler tuning,

avoiding a costly installation of a SNCR (selective

non-catalytic reduction) or SCR (selective catalytic

reduction) reactor.

3.3.2 SOx Emissions

SOx (SO2) emissions reduction may be attributed to

three factors. First, the lower flow rate of dried coal to

the boiler results in a reduction in the amount of S

entering the boiler. Second, a significant portion of the

inorganically bound sulfur is segregated out by the

FBD. Finally, the lower volumetric flow of flue gas

allows a larger proportion of flue gas to be scrubbed

(with less being bypassed), further reducing SO2

emissions (Fig. 4).

The resulting 40% reduction in SO2 emissions

allowed Coal Creek to meet its new SO2 emissions

limits without installing additional scrubber module.

3.3.3 Hg Emissions and Speciation

Flue gas Hg concentration and Hg speciation were

Fig. 4 SO2 removal in the FGD before and after implementation of DryFining.

measured using wet impinger-based sCEMs

(semi-continuous emissions monitors) at the APH inlet,

FGD inlet and outlet, FGD bypass, and stack. Sorbent

trap measurements were conducted for quality control

at the FGD inlet and outlet, and FGD bypass. The

plant CEM was used for continuous measurement of

total mercury, HgT in the stack [8].

Concentration of HgT measured at various locations

before and after implementation of DryFining, is

presented in Fig. 5. With dried coal, concentration of

HgT at the boiler outlet (APH inlet) decreased by

approximately 22% (from 19.2 μg/dNm3 to 15 μg/dNm3

@3% O2), relative to the wet coal baseline. As presented

in Fig. 6, at that location, most of Hg is insoluble

elemental mercury, Hg0. The reduction in HgT at

boiler exit is mainly attributed to the Hg removal in

FBD which lowers mercury content in dried coal by

20%-30%. With DryFining in service, concentration of

HgT across the FGD decreased by more than 30%

(from 13.5 μg/dNm3 to 9.3 g/dNm3 @3% O2). With

wet coal, the decrease in HgT concentration across the

FGD was significantly smaller, approximately 16%

(from 16 μg/dNm3 to 13.5 g/dNm3 @3% O2).

This change in native mercury removal in the FGD is

mostly due to the change in mercury speciation (Fig. 6).

With dried coal, water-soluble oxidized mercury,

Hg2+ at the FGD inlet was 41% of the total mercury,

while with wet coal, Hg2+ was significantly

lower, approximately 27% of the total (Fig. 6). This

increase in Hg2+ may be attributed to lower flue gas


532

Fig. 5 Total mercury concentration at various locations measured before and after implementation of DryFining.

Fig. 6 Mercury speciation before and after implementation of DryFining.

temperatures leaving the APH (increased quench rate)

and lower flue gas moisture content (both are

promoting oxidation of Hg0).

While, some of Hg0 and Hg2+ is adsorbed on the fly

ash particles and removed in the ESP, most of the

water-soluble Hg2+ is removed in the FGD (approx. 90%

and 75% with dried and wet coal, respectively).

The change in Hg speciation combined with the

increase in flue gas flow rate treated by the FGD

resulted in approximately 40% reduction in HgT

emissions (from 14 μg/dNm3 to 8.6 μg/dNm3 @3% O2),

compared to the wet coal (Fig. 5). The concentration of

HgT measured at the stack is higher compared to the

FGD outlet because HgT concentration in the FGD

bypass flow is about the same as at the FGD inlet.

The effect of DryFining on native Hg removal in the

pollution control system at Coal Creek is presented in

Fig. 7.

Fig. 7 Native mercury removal before and after implementation of DryFining.

In addition, with dried coal, reduction of Hg2+

captured in the FGD and it re-emission from the

scrubber liquor in form of Hg0 was significantly

reduced (Fig. 7) further contributing to the reduction in

HgT. The emitted HgT at Coal Creek is 95% Hg0 and

5% Hg2+.

In summary, the 35%-40% reduction in HgT

emissions produced by DryFining is due to the lower

flow rate of dried coal into the plant, removal of the

pyrite-bound mercury from the coal in the FBD,

change in mercury speciation, and increased flow rate

of flue gas through the FGD, where oxidized mercury

(Hg2+) is removed.

The reduction in HgT emissions has allowed Coal

Creek Station to meet its Hg emission limits with

FGD additives to reduce Hg2+ re-emission, thereby

avoiding injection of powdered activated carbon.

4. Long-Term Operating Experience

DryFining has been in continuous commercial

operation at Coal Creek Station for over four years,

achieving availability higher than 95%, and not causing

a single unit outage.

The HHV values for the AR (as-received) and

DryFining product coals and their blend to the feeders

are presented in Fig. 8. During the last two years of

operation, on average approximately 95% of the total

coal input was refined, while 5% was bypassed and

blended with the refined coal. Coal bypass occurs as a

result of maintenance on a coal dryer. As the results


533

Fig. 8 Higher heating value of as-received and refined coals.

show, following the initial operating period,

DryFining process has achieved projected availability

of higher than 95%. To date DryFining system has

refined 26 million tons of raw lignite supplied by the

Falkirk mine.

Moisture removal hovered around the targeted rates.

Tiered targets were established for the first six years,

reaching the ultimate target of 11.25%4 in the seventh

year.

The coal cleaning part of DryFining system worked

well and required little maintenance. Reductions in

sulfur concentration in the coal feed to the boiler have

been measured and demonstrated on a daily basis.

No or very little thinning of the in-bed HXE walls

was detected. Wall thickness measurements were

conducted during each major outage. The NDE

(non-destructive) readings approximated the OEM

(original equipment manufacturer) wall thicknesses.

This confirmed that a proper design of the in-bed HXE

has a major effect on wear intensity.

In addition, inspection and wall thickness

measurements of the low-temperature HXEs, operating

partially below the acid dewpoint temperature did not

indicate corrosion or wall thinning. This is because of

the low sulfur content of the coal and high alkaline

content of the ash. The alkaline ash, coating the tubes,

4The target level of coal moisture removal was set based on the analysis of the boiler convection pass performance, performed by an OEM. It represents the maximum moisture reduction at which steam temperature set points can be maintained.

is neutralizing deposited sulfuric acid and protecting

HXE from the gas-side corrosion.

The particulate control system, a baghouse,

performed above expectations. Due to the high

humidity of the fluidizing air leaving the dryers, it was

expected that, useful life of the bags in the bag houses

would be approximately three years. Bag house

inspection and bag testing, conducted during each

outage, have demonstrated that the bag life is

decreasing by only about 15%/year of operation. If this

trend continues, the expected bag life will be

significantly longer than expected.

4.1 Unit and Station Performance

The performance of both units at Coal Creek

continued to improve since commercial operation of

DryFining began in December 2009. Fig. 9 offers a

comparison of monthly average net unit heat rate

values, determined by the input/output method. The

average annual improvement in net unit heat rate for

Unit 1 is 3.4%—virtually the same as measured during

the baseline tests. The heat rate improvement for Unit 2

of 5.8% is higher because it also includes the effect of a

steam turbine upgrade.

The station net generation has increased since

implementing DryFining since the auxiliary power use

by each unit has decreased 5 MW.

In addition, it can be noted that, implementation of

DryFining has significantly reduced seasonal variations

Fig. 9 Monthly average net unit heat rate for refined (2013) and wet (2009) coals.


534

in unit performance. This is because the coal and

combustion air are entering the boiler envelope at

nearly constant temperature year around. Prior to the

implementation of DryFining, temperature of inlet coal

and air varied significantly from winter to summer.

Therefore, as expected, with DryFining, the heat rate

improvement is more pronounced in the winter,

compared to the summer. The values of net unit heat

rate for April, May and December 2013 are a little

higher for Unit 1 due to extended outages during these

time periods.

4.2 Unit Emissions

Annual averages of NOx and SOx emissions

(measured by the plant CEMs) for the Coal Creek

Station are presented in Fig. 10 for the 2005-2013 time

period.

Following implementation of DryFining, the SOx

emissions were reduced by 44%-46%, while the NOx

emissions were reduced by 24%-25%, compared to the

2005-2009 average. The long-term reduction in NOx

was smaller compared to the test results presented in

Table 3, because changes in unit load and combustion

settings, experienced in regular operation, increase NOx.

4.3 Effect of Coal Drying on Major Plant Equipment

Implementation of DryFining coal drying and

refining system had positively affected performance of

all components in the gas path, from the boiler to the

stack. Changes in operation of APHs, mills, and PA

fans are summarized in Table 4.

Fig. 10 NOx and SO2 emissions before and after implementation of DryFining.

Table 4 Operating parameters: air preheaters, mills and primary air fans.

Parameter Units Prior to DryFining With DryFining

Air preheater (APH)

APH gas outlet temp. oF 340-380 290-320

APH gas-side pressure drop inches w.g. 10-15 5-8

APH primary air pressure drop inches w.g. 8-12 2-3

APH air leakage % 8-15 5-6

klb/hr 840 396

Primary air (PA) fan

PA Fan discharge pressure inches w.g. 48-52 40-42

PA flow to mills klb/hr 2,840-2,920 1,860

Reduction in PA flow % NA ~ 30

Mills

Number of mills at full load 7-8 6

Primary air flow klb/hr-mill 360 310

Mill capacity klb/hr 156 165

Inlet coal temperature oF 35-65 100

Mill power kWh/ton 9 8

Coal flow at full load klb/hr 945-1,000 840-900

Bowl pressure drop inches w.g. 8-11 7-10

Total mill coal flow between overhauls 106 tons 2.4 3.3


535

4.3.1 Boiler

The lower flow rate of refined coal and its lower

moisture content have reduced the convective path flue

gas flow, heat capacity of the flue gas, and convection

heat transfer coefficient. To maintain the reheat steam

temperature setpoints, the combustion control system

has increased main burner tilts and closed attemperator

valves. Total sootblowing steam flow has remained

constant, although the usage split changed. The

frequency of cleaning furnace waterwalls decreased

while cleaning frequency for the convective path

increased to improve steam temperatures.

4.3.2 APH

Each unit at Coal Creek is equipped with two

Ljungstrom trisector APHs. Prior to the

implementation of DryFining, the APHs experienced

high differential pressure (∆P) across the primary air

and flue gas sectors. This was a result of high flows and

fouling of the heat transfer passages in the APH CE

(cold end) layer. The high moisture content of the flue

gas along with seasonal variations in the air inlet

temperatures were major culprits of fouling and

corrosion of the APH CE layer heat transfer surfaces,

which needed replacement every three years. The high

Ps also resulted in high levels of air to gas-side

leakage. DryFining virtually eliminated those problems,

reducing the ID fan power and the PA airflow.

4.3.2 Mills and Coal Pipes

Each unit at Coal Creek is equipped with eight CE

roller mills which feed eight corners of a dual furnace

CE boiler (64 burners). Prior to the implementation of

DryFining, seven mills were normally run (eight were

required for full load in cold weather). Feeder trips,

caused by large pieces of coal, rocks, and tramp iron

stalling the feeder, were frequent occurrences resulting

in load derate and numerous feeder belt replacements.

High PA flows, required to maintain mill exit

temperatures, resulted in high velocities in the coal

pipes and increased erosion. Also, due to the high PA

flow, the mill classifiers were set to low to increase

internal mill circulation and maintain coal fineness

resulting in increased mill power requirements.

DryFining has allowed each unit at Coal Creek to

operate at full load with six mills and reduced PA flow.

With lower PA flow, the mill classifier settings were

increased, causing a decrease in the internal mill

recirculation, increase in the mill capacity, reduction in

mill power, and reduction of mill wear and mill

maintenance. Mill feeder trips have been eliminated,

and plant availability has improved.

4.3.3 PA Fans

Each unit at Coal Creek is equipped with two

primary air fans employing IGV (inlet guide vane) to

control pressure at the APH outlet. The reduction in the

APH P, APH leakage and PA flow to the mills had a

large positive impact on the PA power and spare

capacity.

4.3.4 ID Fans

Each unit at Coal Creek is equipped with four ID

centrifugal fans with VFD (variable frequency drive)

flow control. After implementation of DryFining, the

ID fan power has been reduced between 2-4 MW per

unit due to lower flow rate of the flue gas, lower drafts,

higher flue gas density, and reduced APH fouling.

4.3.5 FGD System (Scrubber)

Each unit at CCS is equipped with a four-module

WFGD (wet flue gas desulphurization) system that was

initially designed to scrub 60% of the flue gas from the

unit. Modification to the scrubber in the late 90 s

allowed scrubbed flow to be increased to 75%.

Implementation of DryFining allowed scrubbed flow

to be increased to 85%. The short-terms tests performed

in 2013 indicated that, 100% scrubbing may be achieved

without the need to install a fifth scrubber module.

4.3.6 ESP

The reduction in the flue gas temperature (Table 2)

has decreased resistivity of the fly ash which, for the

low-rank coals is on a high side, thereby improving

ESP performance. The reduced volume of the flue gas

decreased its velocity and increased the specific

collection area. These effects combined with reduced

particulate loading helped to improve the ESP


536

collection efficiency over the past four years.

5. Avoided Capital Expenditures

As previously stated, in 1990, GRE compared a

conventional approach (compliance options) to

meeting new mercury emission regulations and

regional haze limits which would have required

installation of the air pollution control equipment to

reduce NOx and SOx emissions and meet mercury

emission limits, to the coal beneficiation alternative.

The conventional approach assumed installation of the

fifth scrubber module, COHPAC (compact hybrid

particulate collector), and SNCR on both units, and

second generation of SOFA on Unit 1 (Unit 2 was

already equipped with second generation of SOFA.

The cumulative costs of the considered options are

compared in Fig. 11 as functions of time.

The DryFiningTM fuel enhancement system pays for

itself with lower capital costs, higher plant efficiency,

and ability to remove a portion of the sulfur and

mercury in the coal prior to combustion, and having

numerous positive effects on operation and

performance of the plant air pollution control system.

The combination of all the effects allowed Coal Creek

to meet current emission limits without installing

additional pollution control systems and equipment.

By implementing DryFining at Coal Creek, GRE

avoided $366 million in capital expenditures, which

Fig. 11 Cost comparison of DryFining and emission compliance options at Coal Creek.

would otherwise be needed to comply with emission

regulations.

6. International and Domestic Markets

There has been significant interest in coal drying

over the past several years, especially in overseas

markets experiencing high electrical load growth

combined with large local resources of low-rank coals.

Various lignites and sub-bituminous coals have been

analyzed and tested by GRE through the pilot dryer in

Underwood, North Dakota. Drying kinetics of tested

coal samples was similar, starting with the removal of

surface moisture, followed by progressive removal of

intrinsic moisture. The segregation of coal impurities

was more fuel-specific, depending upon whether and

how much of the sulfur was organically bound and the

amount of clays. For most of the coals, segregation of S

and Hg was of the similar magnitude, as for the Falkirk

lignite.

Thermal integration analyses have been conducted

for a variety of plants and applications including:

sub-critical retrofits along with new supercritical,

oxy-fired [10] and dry-feed gasification platforms,

including CTL (coal-to-liquid) plant [11], requiring

constant moisture content in the gasifier feed. The

results show that the DryFiningTM fuel enhancement

system can be integrated into all analyzed power

generation systems to improve their performance and

operation.

Up to recently, retrofit opportunities in North

America have been limited due to uncertainty in

emissions regulations. The clean power regulations to

be promulgated under Section 111(d) of CAA (clean

air act), and “Building Blocks” for the states expect 6%

reduction in CO2 emissions from existing coal-fired

power plants. This is a formidable goal for the power

generation industry. DryFining provides an option for

significant heat rate improvement and CO2 emission

reduction to power plants burning lignite and

sub-bituminous coals.

GRE continues to actively support the commercial


537

development of new plant opportunities in Southeast

Asia and Eastern Europe, and retrofit to existing power

plants in the U.S.

7. Conclusions

A novel low-temperature coal drying and cleaning

process employing a moving bed fluidized bed dryer

and using waste heat to decrease moisture content of

high-moisture coals was developed in the U.S. by a

team led by GRE. The technology was commercialized

by GRE in 2009, and is available under trade name

DryFiningTM fuel enhancement process. DryFining has

been in continuous commercial operation at GRE’s

Coal Creek Station since December 2009. To date

DryFining has refined 26 million tons of raw lignite

supplied by the Falkirk mine.

In addition to improving net unit heat rate by 3.5%,

implementation of DryFining at Coal Creek has

resulted in substantial reductions in NOx emissions

(25%), SO2 emissions (> 40%), and Hg (35%-40%),

thus avoiding installation of an SNCR or SCR,

additional scrubber module, and injection of powdered

activated carbon.

By implementing DryFining at Coal Creek, GRE

avoided $366 million in capital expenditures, would

otherwise be needed to comply with emission

regulations.

DryFining may be retrofitted to the existing PCC

plants, integrated into the newly build PCC plants, and

coal gasification (IGCC and CLT) and low rank

coal-fired oxyfuel power plants employing dry feed

oxygen-blown gasifiers.

Implementation of DryFining into the newly built

power plants operating with high steam parameters is

especially beneficial for units burning the low rank

coals, since their efficiency is severely affected by the

high coal moisture content. A reduction of coal

moisture is necessary to achieve the full benefits of the

advanced PCC technologies.

Thermal integration of DryFining with an existing

power plant is site-specific and depends on the

available heat sources, space constraints, and general

layout of the plant.

DryFining may also be very effectively used to

improve quality of washed coals, and improve

efficiency and capacity of the plants that have switched

from bituminous to sub-bituminous (PRB) coals to

reduce SO2 emissions.

The benefits of coal drying, such as heat rate

improvement, increase as moisture content of the raw

coal and reduction in coal moisture increase.

In summary, the DryFiningTM process at Coal Creek

has met or exceeded expectations in terms of

availability, plant performance improvement,

emissions reduction, maintenance, and positive effect

on almost all aspects of unit operation including

improvement in availability.

References

[1] US DOE (Department of Energy). 2002. “Lignite Fuel

Enhancement.” US DOE.

[2] Dong, N. 2014. Techno-economics of Modern Pre-drying

Technologies for Lignite-Fired Power Plants. IEA Clean

Coal Centre report CCC/241. Accessed September 24,

2014. http://www.iea-coal.org.

[3] Bullinger, C. W., Ness, M., Sarunac, N., and Levy, E. K.

2002. “Coal Drying Improves Performance and Reduces

Emissions.” Presented at the 27th International

Conference on Coal Utilization & Fuel Systems,

Clearwater, FL, USA.

[4] Ness, M., Krumwiede, J., and Weinstein, R. 2004. “Pilot

Fluidized Bed Coal Dryer: Operating Experience and

Preliminary Results.” Presented at the 29th International

Conference on Coal Utilization & Fuel Systems,

Clearwater, FL, USA.

[5] Bullinger, C. W., and Sarunac, N. 2006. Lignite Fuel

Enhancement. Final Technical report.

[6] Sarunac, N., Ness, M., and Bulllinger. 2007. “One-Year

Operating Experience with a Prototype Fluidized Bed

Coal Dryer at Coal Creek Generating Station.”

Presented at the Third International Conference on

Clean Coal Technologies for our Future, Cagliari, Sardinia,

Italy.

[7] Sarunac, N., Levy, E. K., Ness, M., Bullinger, C. W.,

Mathews, J. P., and Halleck, P. 2010. “A Novel Fluidized

Bed Drying and Density Segregation Process for

Upgrading Low-Rank Coals.” International Journal of

Coal Preparation and Utilization 29 (6): 317-32.


538

[8] Bullinger, C. W., and Sarunac, N. 2010. Lignite Fuel Enhancement. Final technical report.

[9] Bullinger, C. W., Ness, M., Dombrowski, K., Sarunac, N., Archer, G., Gollakota, S., and Chang, R. 2010. “Effect of DryFiningTM Low Temperature Coal Drying Process on Emissions from a Coal-Fired Power Plant.” Presented at the MEGA Symposium, Baltimore, MD, USA.

[10] Ifwer, K., Wolf, J., Anheden, M., Sarunac, N., Charlie Bullinger, C. W., Ness, M., and Höhne, O. 2008. “Air/Nitrogen Lignite Dryer as an Alternative to a Steam Dryer in a Power Plant Using Oxyfuel Technique for CO2

Capture.” Presented at the 33rd International Conference on Coal Utilization & Fuel Systems, Clearwater, FL, USA.

[11] Sarunac, N., Levy, E. K., Bullinger, C. W., and Ness, M. 2008. “A Low-Temperature Coal Drying Process Provides Dry Feed to a Coal-to-Liquids Plant, Improves Performance of a Supercritical Pulverized Lignite-Fired Power Plant, and Increases Value of Washed High-Moisture Illinois Coals.” Presented at the 33rd International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, USA.

four years of operating experience with dryfining fuel ... · pdf filefour years of operating...

Documents